1. Field of the Invention
This invention relates to a method for removal of hydrogen sulfide from a hydrogen sulfide containing gaseous stream utilizing a hydrogen sulfide scavenging agent distributed over a high surface area contactor disposed within the stream of hydrogen sulfide containing gas. More particularly, this invention is related to a method for removal of hydrogen sulfide from natural gas utilizing a high surface area contactor for providing intimate contact between hydrogen sulfide scavenging agent liquids and the natural gas. This method is particularly suitable for natural gas streams containing small amounts of hydrogen sulfide, typically less than about 200 ppm of hydrogen sulfide.
2. Description of Prior Art
Substantial amounts of sour natural gas are currently being produced from natural gas wells, oil wells (as associated gas), and from natural gas storage reservoirs that have been infected with H.sub.2 S-producing bacteria. The presence of hydrogen sulfide in fuel and other gaseous streams has long been of concern for both the users and the producers of such gaseous streams. For example, in the case of natural gas, historically about 25% of the natural gas produced in the United States has been sour, that is, containing greater than about 4 ppmv H.sub.2 S (5.7 mg H.sub.2 S/m.sup.3). In addition to the corrosive and other adverse effects that such impurities have upon equipment and processes with which such gaseous streams interact, noxious emissions are commonly produced from combustion of the natural gas as a result of oxidation of the hydrogen sulfide. The resulting sulphur oxides are a major contributor to air pollution and may have detrimental impact upon humans, animals, and plant life. Increasingly stringent federal and state regulations have accordingly been promulgated in an effort to reduce or eliminate sulphurous emissions, and a concomitant interest exists in efficiently removing from natural gas streams and the like the hydrogen sulfide that comprises a significant precursor of the emissions.
A growing segment of the natural gas industry uses H.sub.2 S scavenging processes to remove low concentrations of H.sub.2 S (usually less than about 100 ppm) from subquality natural gas at remote locations. For this gas segment, conventional amine sweetening is not economically feasible, particularly when carbon dioxide (CO.sub.2) removal is not required. Historically, the natural gas production industry has used nonregenerable scavenging processes to treat this gas. In these processes, a scavenging agent reacts irreversibly with H.sub.2 S. The reaction products are subsequently separated from the treated sweet gas and discarded.
Hydrogen sulfide scavenging agents are most commonly applied through one of the following three methods: (1) batch application of liquid scavenging agents in a sparged tower contactor; (2) batch application of solid scavenging agents in a fixed-bed contactor; or (3) continuous direct injection of liquid scavenging agents. Studies of batch applications of liquid and solid scavenging agents have shown that scavenging chemical costs are lower for an iron-oxide-based solid scavenger than for an amine-based liquid scavenger. However, for natural gas with less than approximately 25 ppm H.sub.2 S, a direct-injection approach has the potential for the lowest overall costs because of its low capital cost relative to batch applications. Given the estimated $50 million per year in H.sub.2 S scavenging chemical costs in the United States, significant cost savings are realizable from an H.sub.2 S scavenging process utilizing continuous direct-injection of scavenging agents into the gaseous stream to be treated over conventional batch direct-injection scavenging applications.
Studies have been conducted which show that the performance of direct-injection scavenging systems is more difficult to predict than tower-based systems because the underlying fundamentals of direct injection are largely unknown. In addition, H.sub.2 S removal results, chemical usage, and chemical costs are highly site-specific, especially with regard to gaseous fluid velocity, liquid-gas mixing conditions, and contact time.